Methods of forming downhole tools having features for reducing balling

ABSTRACT

Downhole tools with a topographical pattern, and anti-balling material over the topographical pattern. The topographical pattern may be defined by at least one of a plurality of recesses extending into a surface of a body of the tool and a plurality of protrusions protruding from the surface. Downhole tools include an insert disposed within a recess in a body, and the insert comprises an anti-balling material having a composition selected to reduce accumulation of formation cuttings on the tools when the tools are used to form or service a wellbore. Downhole tools include anti-balling material disposed over a porous mass provided over the surfaces of the tools. Methods of forming downhole tools include providing anti-balling material over features on and/or in a surface of a body of a tool. Methods of repairing downhole tools include removing an insert therefrom and disposing a replacement insert therein.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application is a divisional of U.S. patent application Ser. No.14/656,080, filed Mar. 12, 2015, now U.S. Pat. No. 9,551,191, issuedJan. 24, 2017, which is a divisional of U.S. patent application Ser. No.13/006,323, filed Jan. 13, 2011, now U.S. Pat. No. 8,985,244, issuedMar. 24, 2015, which application claims the benefit of U.S. ProvisionalPatent Application Ser. No. 61/295,989, filed Jan. 18, 2010, titled“Drill Bits and Other Downhole Tools Having Features for ReducingBalling, and Related Methods.” The subject matter of this application isalso related to the subject matter of U.S. patent application Ser. No.14/849,802, filed Sep. 10, 2015, now U.S. Pat. No. 9,593,539, issuedMar. 14, 2017, titled “Methods of Forming Downhole Tools Having Featuresfor Reducing Balling,” which application is a divisional of U.S. patentapplication Ser. No. 13/454,865, filed Apr. 24, 2012, now U.S. Pat. No.9,157,283, issued Oct. 13, 2015, titled “Downhole Tools Having Featuresfor Reducing Balling, and Methods of Forming Such Tools,” whichapplication is a continuation of U.S. patent application Ser. No.13/006,323, now U.S. Pat. No. 8,985,244, issued Mar. 24, 2015. Thedisclosures of each of these applications are incorporated in theirentirety herein by this reference.

TECHNICAL FIELD

Embodiments of the present invention relate to downhole tools, such asearth-boring rotary drill bits, and, more particularly, to downholetools having features for reducing the adhesion of formation cuttingsthereto during the formation of a wellbore, and to methods of formingsuch downhole tools.

BACKGROUND

Wellbores are formed in subterranean formations for various purposesincluding, for example, extraction of oil and gas from the subterraneanformation and extraction of geothermal heat from the subterraneanformation. Wellbores may be formed in a subterranean formation using adrill bit such as, for example, an earth-boring rotary drill bit.Different types of earth-boring rotary drill bits are known in the artincluding, for example, fixed-cutter bits (which are often referred toin the art as “drag” bits), rolling-cutter bits (which are oftenreferred to in the art as “rock” bits), diamond-impregnated bits, andhybrid bits (which may include, for example, both fixed cutters androlling cutters). The drill bit is rotated and advanced into thesubterranean formation. As the drill bit rotates, the cutters orabrasive structures thereof cut, crush, shear, and/or abrade away theformation material to form the wellbore. A diameter of the wellboredrilled by the drill bit may be defined by the cutting structuresdisposed at the largest outer diameter of the drill bit.

The drill bit is coupled, either directly or indirectly, to an end ofwhat is referred to in the art as a “drill string,” which comprises aseries of elongated tubular segments connected end-to-end that extendsinto the wellbore from the surface of the formation. Often various toolsand components, including the drill bit, may be coupled together at thedistal end of the drill string at the bottom of the wellbore beingdrilled. This assembly of tools and components is referred to in the artas a “bottom hole assembly” (BHA).

The drill bit may be rotated within the wellbore by rotating the drillstring from the surface of the formation, or the drill bit may berotated by coupling the drill bit to a downhole motor, which is alsocoupled to the drill string and disposed proximate the bottom of thewellbore. The downhole motor may comprise, for example, a hydraulicMoineau-type motor having a shaft, to which the drill bit is mounted,that may be caused to rotate by pumping fluid (e.g., drilling mud orfluid) from the surface of the formation down through the center of thedrill string, through the hydraulic motor, out from nozzles in the drillbit, and back up to the surface of the formation through the annularspace between the outer surface of the drill string and the exposedsurface of the formation within the wellbore.

It is known in the art to use what are referred to in the art as“reamer” devices (also referred to in the art as “hole opening devices”or “hole openers”) in conjunction with a drill bit as part of a bottomhole assembly when drilling a wellbore in a subterranean formation. Insuch a configuration, the drill bit operates as a “pilot” bit to form apilot bore in the subterranean formation. As the drill bit and bottomhole assembly advances into the formation, the reamer device follows thedrill bit through the pilot bore and enlarges the diameter of, or“reams,” the pilot bore.

The bodies of downhole tools, such as drill bits and reamers, are oftenprovided with fluid courses, such as “junk slots,” to allow drilling mud(which may include drilling fluid and formation cuttings generated bythe tools that are entrained within the fluid) to pass upwardly aroundthe bodies of the tools into the annular space within the wellbore abovethe tools outside the drill string. Drilling tools used for casing andliner drilling usually have smaller fluid courses and are particularlyprone to balling, causing a lower rate of penetration.

When drilling a wellbore, the formation cuttings may adhere to, or“ball” on, the surface of the drill bit. The cuttings may accumulate onthe cutting elements and the surfaces of the drill bit or other tool,and may collect in any void, gap, or recess created between the variousstructural components of the bit. This phenomenon is particularlyenhanced in formations that fail plastically, such as in certain shales,mudstones, siltstones, limestones and other relatively ductileformations. The cuttings from such formations may become mechanicallypacked in the aforementioned voids, gaps, or recesses of the drill bit.In other cases, such as when drilling certain shale formations, theadhesion between formation cuttings and a surface of a drill bit orother tool may be at least partially based on chemical bondstherebetween. When a surface of a drill bit becomes wet with water insuch formations, the bit surface and clay layers of the shale may sharecommon electrons. A similar sharing of electrons is present between theindividual sheets of the shale itself. A result of this sharing ofelectrons is an adhesive-type bond between the shale and the bitsurface. Adhesion between the formation cuttings and the bit surface mayalso occur when the charge of the bit face is opposite the charge of theformation. The oppositely charged formation particles may adhere to thesurface of the bit. Moreover, particles of the formation may becompacted onto surfaces of the bit or mechanically bonded into pits ortrenches etched into the bit by erosion and abrasion during the drillingprocess.

In some cases, drilling operations are conducted with reduced ormitigated hydraulics. For example, some rigs may not have large pumpsfor drilling to the depths required. Furthermore, operators sometimesfind it too costly to run higher mud flow rates or find that high flowrates cause more wear and tear to the BHA. Drilling with reduced ormitigated hydraulics has a tendency to cause balling.

Attempts have been made to reduce the likelihood of balling in downholetools, as disclosed in, for example, U.S. Pat. No. 5,651,420, whichissued Jul. 29, 1997, to Tibbitts et al., and U.S. Pat. No. 6,260,636,which issued Jul. 17, 2001, to Cooley et al.; and U.S. Pat. No.6,450,271, which issued Sep. 17, 2002, to Tibbitts et al.

BRIEF SUMMARY

In some embodiments, the present invention includes a downhole tool witha body having a surface with a topographical pattern defined by at leastone of a recess extending into the surface and a protrusion protrudingfrom the surface. The tool also includes an anti-balling materialdisposed over at least a portion of the surface comprising the pattern.The anti-balling material may have a composition selected to reduceaccumulation of formation cuttings thereon when the downhole tool isused to form or service a wellbore.

In certain embodiments, a downhole tool may include a body having asurface having at least one recess extending into the surface of thebody and an insert disposed within the at least one recess. The insertmay comprise an anti-balling material having a composition selected toreduce accumulation of formation cuttings thereon when the downhole toolis used to form or service a wellbore.

In some embodiments, a downhole tool may include a body having asurface, at least one porous mass over the surface of the body; and ananti-balling material disposed over the at least one porous mass. Theanti-balling material may have a composition selected to reduceaccumulation of formation cuttings thereon when the downhole tool isused to form or service a wellbore.

Methods of forming a downhole tool may include forming at least one of arecess extending into a body of the downhole tool and a protrusionprotruding from the body of the downhole tool. Methods may furtherinclude providing an anti-balling material over at least a portion ofthe surface and selecting the anti-balling material to have acomposition for reducing accumulation of formation cuttings thereon whenthe downhole tool is used to form or service a wellbore. The downholetool may include a surface that extends into or over the recess orprotrusion.

Methods of forming a downhole tool may include providing a porous massover a surface of a body of the downhole tool, providing an anti-ballingmaterial over at least a portion of the porous mass, and selecting theanti-balling material to have a composition for reducing accumulation offormation cuttings thereon when the downhole tool is used to form orservice a wellbore.

Methods of forming a downhole tool may also include forming a recess ina surface of a body of the downhole tool, forming an insert comprisingan anti-balling material, selecting the anti-balling material to have acomposition for reducing accumulation of formation cuttings thereon whenthe downhole tool is used to form or service a wellbore, disposing theinsert within the recess, and attaching the insert to the body of thedownhole tool.

Methods of repairing a downhole tool may include removing an insert froma recess of the downhole tool, disposing a replacement insert within therecess, and attaching the replacement insert to the body of the downholetool. The replacement insert may have an anti-balling material selectedto have a composition for reducing accumulation of formation cuttingsthereon when the downhole tool is used to form or service a wellbore.

BRIEF DESCRIPTION OF THE DRAWINGS

While the specification concludes with claims particularly pointing outand distinctly claiming what are regarded as embodiments of the presentinvention, various features and advantages of this invention may be morereadily ascertained from the following description of exampleembodiments of the invention provided with reference to the accompanyingdrawings, in which:

FIG. 1 is a perspective view of an embodiment of a downhole tool of thepresent invention, which includes an anti-balling material attachedthereto using features and methods described herein;

FIG. 2 is an enlarged view of a portion of FIG. 1, and illustrates atexture or pattern on an exterior surface of the tool of FIG. 1 overwhich the anti-balling material may be disposed;

FIG. 3 is a cross-sectional view of a portion of the tool shown in FIGS.1 and 2, taken along the section line 103-103 shown in FIG. 2;

FIG. 4 is similar to FIG. 2, and illustrates another texture or patternthat may be formed on an exterior surface of a tool in accordance withadditional embodiments of the present invention for improving adherenceof anti-balling material to such tools;

FIG. 5 is a cross-sectional view like that of FIG. 3, and illustratesadditional embodiments of the present invention taken along the sectionline 105-105 shown in FIG. 4;

FIG. 6 is similar to FIGS. 2 and 4, and illustrates yet another textureor pattern that may be formed on an exterior surface of a tool inaccordance with additional embodiments of the present invention forimproving adherence of anti-balling material to such tools;

FIG. 7 is a cross-sectional view like that of FIGS. 3 and 5, butillustrates a portion of the tool shown in FIG. 6 taken along sectionline 107-107 shown therein;

FIG. 8 is similar to FIGS. 2, 4, and 6, and illustrates yet anothertexture or pattern that may be formed on an exterior surface of a toolin accordance with additional embodiments of the present invention forimproving adherence of anti-balling material to such tools;

FIG. 9 is a cross-sectional view like that of FIGS. 3, 5, and 7, butillustrates a portion of the tool shown in FIG. 8 taken along sectionline 109-109 shown therein;

FIG. 10A is a perspective view of a portion of the tool shown in FIGS. 8and 9;

FIG. 10B is a perspective view showing enlarged detail of a portion ofthe tool shown in FIGS. 8 through 10B, shown within the area of circle111;

FIG. 11 is a perspective view of a portion of a tool in accordance withan embodiment of the present invention;

FIG. 12 is similar to FIGS. 2, 4, 6, and 8, and illustrates yet anothertexture or pattern that may be formed on an exterior surface of a toolin accordance with additional embodiments of the present invention forimproving adherence of anti-balling material to such tools;

FIG. 13 is a cross-sectional view like that of FIGS. 3, 5, 7, and 9, butillustrates a portion of the tool shown in FIG. 12 taken along sectionline 113-113 shown therein;

FIGS. 14 through 17 are perspective views of various displacementmembers that include a template texture or pattern for forming acomplementary texture or pattern on and/or in an exterior surface of adownhole tool, like that shown in FIG. 1, during an infiltration orcasting process used to form the downhole tool within a mold.

FIG. 18 is a perspective view illustrating anti-balling material appliedto an exterior surface of a downhole tool like that of FIG. 1 over atexture or pattern provided on the surface in accordance withembodiments of the present invention; and

FIG. 19 illustrates an insert that includes an anti-balling material,one or more of which may be secured to a body of a downhole tool inaccordance with additional embodiments of the invention.

DETAILED DESCRIPTION

The illustrations presented herein are not actual views of anyparticular downhole tool, drill bit, or component of such a tool or bit,but are merely idealized representations which are employed to describeembodiments of the present invention.

FIG. 1 illustrates an embodiment of a downhole tool of the presentinvention. The downhole tool of FIG. 1 is an earth-boring rotary drillbit 10 having a bit body 11 that includes a plurality of blades 12separated from one another by fluid courses 13. The portions of thefluid courses 13 that extend along the radial sides (the “gage” areas ofthe drill bit 10) are often referred to in the art as “junk slots.” Aplurality of cutting elements 14 are mounted to each of the blades 12.The bit body 11 further includes a generally cylindrical internal fluidplenum and fluid passageways that extend through the bit body 11 to anexterior surface 16 of the bit body 11. Nozzles 18 may be secured withinthe fluid passageways proximate the exterior surface 16 of the bit body11 for controlling the hydraulics of the drill bit 10 during drilling.

During a drilling operation, the drill bit 10 may be coupled to a drillstring (not shown). As the drill bit 10 is rotated within the wellbore,drilling fluid may be pumped down the drill string, through the internalfluid plenum and fluid passageways within the bit body 11 of the drillbit 10, and out from the drill bit 10 through the nozzles 18. Formationcuttings generated by the cutting elements 14 of the drill bit 10 may becarried with the drilling fluid through the fluid courses 13, around thedrill bit 10, and back up the wellbore through the annular space withinthe wellbore and outside the drill string.

As shown in FIG. 1, an anti-balling material 22, which is represented inFIG. 1 by the cross-hatched areas for purposes of illustration, may bedisposed over at least a portion of the exterior surface 16 of the bitbody 11. The anti-balling material 22 may have a composition selected toreduce accumulation of formation cuttings thereon when the drill bit 10is used to form a wellbore. The anti-balling material 22 may be providedat, for example, regions of the drill bit 10 that are susceptible toballing, such as pinch points (e.g., locations at which bladesconverge), cuttings trajectory points (e.g., locations at which cuttingsconverge), and bit shank (i.e., where the bit head and threaded pinmeet). For example, the anti-balling material 22 may be disposed overone or more regions of the exterior surface 16 of the bit body 11 of thedrill bit 10 within the fluid courses 13, as shown in FIG. 1. Suchregions may include, for example, rotationally leading surfaces 24A ofthe blades 12, rotationally trailing surfaces 24B of the blades, underthe cutting elements 14 where chip flow occurs, and behind the cuttingelements 14. In additional embodiments, the anti-balling material 22 mayform a generally continuous coating disposed over at least substantiallyall exterior surfaces of the bit body 11 of the drill bit 10.

The anti-balling material 22 may comprise, for example, a polymermaterial such as, for example, a fluoropolymer (e.g., a TEFLON®-basedmaterial), a urethane, or an epoxy. In some embodiments, theanti-balling material 22 also may comprise a metal, a metal alloy, or aceramic, such as an alloy of boron, aluminum, and magnesium. In otherembodiments, anti-balling materials may include graphite, molybdenumdisulfide, boron nitride, or silicone. For example, the anti-ballingmaterial 22 may comprise a mixture of a fluoropolymer and a metal ormetal alloy such as, for example, a nickel-based alloy. Anti-ballingmaterials 22 may be selected or formulated based on various properties,such as hydrophobicity, coefficient of friction, ability to bond to abit body 11, etc. For example, an anti-balling material 22 may beselected that is hydrophobic (i.e., having a contact angle with waterdroplets greater than 90°, as determined in accordance with ASTMStandard F21-65, 2007, Standard Test Method for Hydrophobic SurfaceFilms by the Atomizer Test, ASTM Int'l, West Conshohocken, Pa.) and hasa coefficient of friction of about 0.5 or lower (as determined inaccordance with ASTM Standard G115-10, Standard Guide for Measuring andReporting Friction Coefficients, ASTM Int'l, West Conshohocken, Pa.). Insome embodiments, the anti-balling material 22 may have a coefficient offriction of about 0.2 or lower. As a further example, if an anti-ballingmaterial 22 is a fluoropolymer, the anti-balling material 22 may have acoefficient of friction of about 0.04. In some embodiments, theanti-balling material 22 may have a coefficient of friction below 0.04.Examples of commercially available materials that may be used for theanti-balling material 22 include, for example, those sold by SouthwestImpreglon of Humble, Tex., under the names FLUOROSHIELD™ and FLUOROLON®.

In some embodiments, the anti-balling material 22 may comprise diamondor diamond-like carbon (DLC). DLC is an amorphous coating of carbonformulated to have some properties similar to the properties of diamond,such as hardness or chemical stability. DLC contains sp³ hybridizedcarbon atoms that may be arranged in any combination of cubic andhexagonal lattices. For example, DLC may include tetrahedral amorphouscarbon, or ta-C, which consists of only sp³ carbon. DLC may also includefillers, such as hydrogen, sp² carbon, or metals. DLC coatings have nolong-range crystalline order, which may make the coatings more flexibleand able to conform to different shapes. DLC coatings may be chosen fortheir wear resistance, and may have a coefficient of friction againstpolished steel from about 0.05 to 0.20 (as determined in accordance withASTM Standard G115-10).

One particularly suitable process for applying a DLC coating isdisclosed in PCT International Patent Application NumberPCT/GB2008/050102, filed Feb. 15, 2008 and published on Aug. 21, 2008under International Publication Number WO 2008/099220, a copy of theapplication being made a part hereof as Appendix A.

The aforementioned coating process has been implemented for certainapplications by Diamond Hard Surfaces Ltd. of Northamptonshire, GreatBritain. However, the application of the coating process, which resultsin a coating trademarked as the ADAMANT® coating, has not been suggestedfor the application of the present disclosure. It is currently believedthat a coating known as the ADAMANT® 010 coating, or an even more robustimplementation of same, may be especially suitable for use in theapplication of the present disclosure. The coating process may beconducted at temperatures of 100° C. or less, and coatings of a desiredthickness from about 1 μm to about 50 μm thick, depending on thematerial of the substrate to be coated, may be achieved at temperaturesbelow 200° C. In addition, these coatings exhibit excellent adhesion tothe surface of the coated substrate, as well as high conformality andevenness of coverage.

In some embodiments, the anti-balling material 22 may further compriseone or more filler materials such as, for example, whiskers, fibers,particles, etc. As a non-limiting example, in some embodiments, theanti-balling material 22 may comprise one or more of carbon fibers andceramic particles (e.g., particles of oxide material such as aluminumoxide, zirconium oxide, yttrium oxide, zinc oxide, titanium oxide,tantalum oxide, etc.).

In some embodiments, the anti-balling material 22 may comprise a layerof material having an average thickness T_(A) (FIG. 3) greater thanabout 0.13 mm (about 0.005 in), greater than about 0.20 mm (about 0.008in), or even greater than about 3.175 mm (about 0.125 in). In otherembodiments, however, the anti-balling material 22 may comprise a layerof material having an average thickness T_(A) (FIG. 3) of between a fewnanometers (e.g., two nanometers) and about 0.13 mm (about 0.005 in).For example, some anti-balling materials 22 (e.g., DLC coatings orcoatings applied by chemical vapor deposition) may have an averagethickness T_(A) of from about 1 micron (0.001 mm) to about 1000 microns(1.0 mm). As another example, an anti-balling material 22 may be formedto have an average thickness T_(A) of from about 1 micron to about 25mm. In some embodiments, the anti-balling material 22 may even have anaverage thickness T_(A) greater than 25 mm.

In accordance with some embodiments of the present invention, a porousdeposit may be provided over the exterior surface 16 of the bit body 11of the drill bit 10, and the anti-balling material 22 may be disposedover the porous deposit.

For example, FIG. 2 is an enlarged view of a portion of the bit body 11of the drill bit 10 of FIG. 1, and illustrates a porous mass 26 on aregion of the exterior surface 16 of the bit body 11 within a fluidcourse 13. Of course, the porous mass 26 may be provided over any regionof the exterior surface 16 of the bit body 11, including the regions ofthe exterior surface 16 over which the anti-balling material 22 is to bedisposed, as previously discussed in relation to FIG. 1.

In the embodiment of FIG. 2, the porous mass 26 includes a substantiallycontinuous layer of porous material that extends over one or more areasof the exterior surface 16 of the bit body 11 of the drill bit 10. FIG.3 is a cross-sectional view of a portion of the drill bit 10 taken alongsection line 103-103 shown in FIG. 2. As shown in FIG. 3, the layer ofporous material may have an average thickness T_(P) of between, forexample, about 0.0254 mm (about 0.001 in) and about 5.08 mm (about 0.200in). In certain embodiments, the layer of porous material may have anaverage thickness T_(P) of between about 0.13 mm (about 0.005 in) andabout 0.20 mm (about 0.008 in).

By way of example and not limitation, the porous mass 26 may comprise ametal or metal-alloy material (such as, for example, steel, nickelalloy, cobalt alloy, or a nickel aluminide) that is deposited over thebit body 11 using a thermal spray process (e.g., a wire arc sprayprocess, chemical vapor deposition, processes for applying DLC coatings,etc.). In such embodiments, relatively fine particles of metal or metalalloy material may be projected out from a spray gun through an arc orflame, where they may become at least partially melted, and onto theexterior surface 16 of the bit body 11. As they impinge on the exteriorsurface 16, the particles cool, solidify, and are bonded to each otherand the underlying exterior surface 16. The inter-particle spaces,however, may not be completely filled and, thus, result in the porositywithin the porous mass 26. Wear-resistant particles, such as, forexample, tungsten carbide particles, also may be included in the porousmass 26.

After providing the porous mass 26 on the bit body 11, the anti-ballingmaterial 22 previously described in relation to FIG. 1 may be providedover the porous mass 26. The anti-balling material 22, when applied tothe porous mass 26, may infiltrate into pores of the porous mass 26,which may enhance bonding of the anti-balling material 22 to the bitbody 11. The porous mass 26 also may reinforce the anti-balling material22. Thus, by providing the anti-balling material 22 over the porous mass26, the rate at which the anti-balling material 22 wears and/or peelsaway from the bit body 11 during drilling operations may be reduced, andthe useful life of the anti-balling material 22 may be increased. Insome embodiments, the anti-balling material may be deposited over theporous mass 26 using a thermal spray process.

In additional embodiments of the present invention, the porous mass 26may comprise a plurality of porous masses 26 disposed over one or moreregions of the exterior surface 16 of the bit body 11 of the drill bit10, as shown in FIG. 4. In some embodiments, the plurality of porousmasses 26 may define a topographical pattern on the exterior surface 16of the bit body 11. In some embodiments, the plurality of porous masses26 may comprise a plurality of discrete, laterally isolated porousmasses 26, as shown in FIG. 4. Such discrete porous masses 26 may bedisposed in an ordered array over a region of the exterior surface 16 ofthe bit body 11, such as, for example, in an array of rows and columns.In additional embodiments, the discrete porous masses 26 may be randomlypositioned over the exterior surface 16 of the bit body 11. Theanti-balling material 22 may extend beyond the discrete porous masses26, such as in areas prone to balling.

The plurality of porous masses 26 may have any shape, including, forexample, round, oval, square, triangular, or cross-shaped, as shown inFIG. 4. FIG. 5 is a cross-sectional view like that of FIG. 3, butillustrating a plurality of discrete, laterally isolated porous masses26 on the exterior surface 16 of the bit body 11, and the anti-ballingmaterial 22 disposed over the porous masses 26 and the exterior surface16 of the bit body 11.

As shown in FIG. 5, in some embodiments, an exposed major surface 28 ofthe anti-balling material 22 over the porous masses 26 may have a smoothcontour that does not replicate or follow the contour of the underlyingporous masses 26. In other embodiments, however, the exposed majorsurface 28 may replicate or follow the contour of the underlying porousmasses 26, such that the pattern defined by the underlying porous masses26 is visible from the exterior of the drill bit 10.

The discrete, laterally isolated porous masses 26 may be formed insubstantially the same manner, or a substantially similar manner, as thelayer of porous material previously described in relation to FIGS. 2 and3. In a flame spray process, for example, the flame-sprayed material maybe deposited onto the bit body 11 through apertures in a mask. Theapertures in the mask may have a shape corresponding to the desiredshape of the laterally isolated porous masses 26 to be deposited on theexterior surface 16 of the bit body 11.

In accordance with additional embodiments of the present invention, theexterior surface 16 of the bit body 11 of the drill bit 10 may beprovided with a topographical pattern that is defined by at least one ofa plurality of recesses extending into the exterior surface 16 of thebit body 11, and a plurality of protrusions protruding from the exteriorsurface 16 of the bit body 11. The anti-balling material 22 may bedisposed over the topographical pattern. In other words, theanti-balling material 22 may be disposed over at least a portion of theexterior surface 16 that includes the topographical pattern defined bythe recesses and/or protrusions. The topographical pattern may beconfigured to improve retention of the anti-balling material 22 on thebit body 11 during drilling. In other words, the topographical patternmay be configured to improve the life of the anti-balling material 22 onthe bit body 11 of the drill bit 10 during drilling operations.

Referring to FIG. 6, in some embodiments of the invention, recesses 32(e.g., a plurality of recesses 32) may be formed or otherwise providedin the exterior surface 16 of the bit body 11 of the drill bit 10. Asshown in FIG. 6, the recesses 32 may be generally elongated, and, insome embodiments, may be oriented within the fluid course 13 to extendin a direction that is generally transverse to a general direction offluid flow through the fluid course 13 during a drilling operation. Inother embodiments, the recesses 32 may be oriented within the fluidcourse 13 to extend in a direction that is generally parallel to thegeneral direction of fluid flow through the fluid course 13 during adrilling operation. In yet further embodiments, the recesses 32 mayinclude some recesses 32 oriented transverse to the direction of fluidflow through the fluid course 13, and some recesses 32 oriented parallelto the direction of fluid flow through the fluid course 13. For example,in some embodiments, a plurality of crisscrossing elongated recesses 32may be provided in a region of the exterior surface 16 within the fluidcourse 13. In additional embodiments, the recesses 32 may not beelongated, and may have any shape such as, for example, circular, oval,rectangular, square, triangular, etc. Furthermore, in some embodiments,the recesses 32 may comprise a plurality of discrete, laterally isolatedrecesses 32, as shown in FIG. 6. Such discrete recesses 32 may bedisposed in an ordered array over a region of the exterior surface 16 ofthe bit body 11, or they may be randomly located over the exteriorsurface 16 of the bit body 11. Thus, the recesses 32 may be used todefine or provide a texture or pattern on the exterior surface 16 of thebit body 11, which may improve the usable life of the anti-ballingmaterial 22 when the anti-balling material 22 is disposed over thetexture or pattern.

FIG. 7 is a cross-sectional view of a portion of the drill bit 10 ofFIG. 6 taken along section line 107-107 shown in FIG. 6. As shown inFIG. 7, in some embodiments, the recesses 32 may have an average depthD_(R) of about 0.254 mm (about 0.010 in) or more, about 0.381 mm (0.015in or more, or even about 0.762 mm (about 0.030 in) or more. In someembodiments, the recesses 32 may have an average width W_(R) of about0.762 mm (about 0.030 in) or more, or even about 1.5 mm (about 0.060 in)or more. In embodiments in which the recesses 32 are elongated, they mayhave an average length of about 6.35 mm (about 0.25 in) or more, about19.05 mm (about 0.75 in) or more, or even about 38.4 mm (1.5 in) ormore. Though the recesses 32 are shown in FIG. 7 oriented transverse tothe general direction of fluid flow through the fluid course 13 during adrilling operation, recesses 32 may be oriented in a direction generallyparallel to the direction of fluid flow. Recesses 32 may have an averagelength of about 50.8 mm (about 2.0 in) or more, or even about 152.4 mm(about 6.0 in) or more.

The recesses 32 may be formed on the bit body 11 of the drill bit 10using any of a number of techniques. For example, the recesses 32 may bemachined into the exterior surface 16 of the bit body 11 using amachining process, such as a milling process or a drilling process. Suchprocesses may be desirable when the bit body 11 is formed of andcomprises a material, such as steel, that may be machined relativelyeasily. In additional embodiments, bit body 11 may comprise a materialthat is not easily machined. For example, the bit body 11 may comprise aparticle-matrix composite material, such as cobalt-cemented tungstencarbide, which may be relatively difficult to machine. Such bit bodies11 are often formed using an infiltration process, in which the bit body11 is formed using a casting process in a mold. In particular, a mold isformed in a refractory material, such as graphite, for example, and themold is formed to include a mold cavity having a shape corresponding tothe shape of the bit body 11 to be formed therein. In such processes,the recesses 32 may be formed into the exterior surface 16 of the bitbody 11 by providing a surface within the mold cavity that includesprotrusions having a shape corresponding to the recesses 32 to be formedin the bit body 11. As the bit body 11 is then cast within the moldcavity and adjacent the surface that includes the protrusions, theprotrusions will form complementary recesses 32 on the exterior surface16 of the bit body 11 when the bit body 11 is removed from the mold.

Referring to FIG. 8, in some embodiments of the invention, a pluralityof recesses 34 may be formed or otherwise provided in the exteriorsurface 16 of the bit body 11 of the drill bit 10. As shown in FIG. 8,the recesses 34 may be generally shaped as a portion of a sphere, forexample, as a hemisphere. The recesses 34 may comprise a plurality ofdiscrete, laterally isolated recesses 34, as shown in FIG. 8. Suchdiscrete recesses 34 may be disposed in an ordered array over a regionof the exterior surface 16 of the bit body 11, or they may be randomlylocated over the exterior surface 16 of the bit body 11. Thus, therecesses 34 may define or provide a texture or pattern on the exteriorsurface 16 of the bit body 11, which may improve the usable life of theanti-balling material 22 when the anti-balling material 22 is disposedover the texture or pattern.

FIG. 9 is a cross-sectional view of a portion of the drill bit 10 ofFIG. 8 taken along section line 109-109 shown in FIG. 8. As shown inFIG. 9, in some embodiments, the recesses 34 may have an average radiusr_(R) of about 0.254 mm (about 0.010 in) or more, about 2.54 mm (about0.10 in) or more, or even about 25.4 mm (about 1.0 in) or more. In otherembodiments, recesses 34 may have an average radius r_(R) of less thanabout 0.254 mm (about 0.010 in).

FIG. 10A is a perspective view showing a portion of the drill bit 10shown in FIG. 8. The recesses 34 are shown within a fluid course 13between blades 12 of the drill bit 10. In some embodiments, recesses 34′may be placed adjacent to blades 12. The recesses 34 are shown enlargedand in greater detail in FIG. 10B, which includes the portion of thedrill bit 10 shown in FIG. 10A within the area of circle 111. In someembodiments, one or more inserts 36 may be disposed at least partiallywithin recesses 34. As shown in FIG. 10B, inserts 36 may besubstantially spherical. Inserts 36 may be formed to be spheres, withoutsharp edges, thus limiting or avoiding problems associated with breakageof the inserts 36 at their edges or corners. Recesses 34 may be shapedas a portion of a sphere (e.g., as a hemisphere), having only one sharpedge, to limit or avoid breakage of the material of the bit body 11.Recesses 34 and inserts 36 may also be shaped in any other shape, suchas rectangular, triangular, etc. Inserts 36 may be selected to have ananti-balling material on a surface thereof, or may be formed of ananti-balling material. In certain embodiments, inserts 36 may be formedof a metal, a metal matrix, a polymer, or any other material, and may becoated with an anti-balling material. For example, coatings of theanti-balling material may be applied using a thermal spray process(e.g., a wire arc spray process, chemical vapor deposition, processesfor applying DLC coatings, etc.). In some embodiments, inserts 36 mayoverlap recess 34 edges to better protect the edges from wear. In otherwords, the exposed portion of an insert 36 may have a larger dimension(diameter, width, etc.) than the portion of the insert 36 disposedwithin a recess 34. In some embodiments, insert 36 may be formed suchthat the exposed surface of the insert 36 is flush with the surface ofthe surrounding fluid course 13. In other embodiments, the exposedsurface of the insert 36 may be raised or lowered with respect to thesurface of the fluid course 13. A protruding insert 36 having ananti-balling material on a surface thereof may be placed in an area ofthe bit body 11 prone to balling, such that large areas of balling areless likely to form. A protruding insert 36 may have a larger exposedsurface area than an insert 36 that fits within the same recess 34 andis flush with the surrounding fluid course 13. Protruding inserts 36 mayincrease the quantity of anti-balling material in areas prone toballing.

In some embodiments, inserts 36 may be mechanically pressed intorecesses 34. Inserts 36 and/or surfaces defining recesses 34 may beserrated or otherwise treated to increase mechanical strength of theattachment between surfaces defining recesses 34 and inserts 36. Theinserts 36 and/or surfaces defining recesses 34 may be mechanicallyand/or chemically treated to effect bonding. For example, if an insert36 is formed of a fluorocarbon polymer (e.g., TEFLON®), the portion ofthe insert 36 configured to be fitted into a recess 34 may be etched toimprove adhesion to the bit body 11. Etching may include exposing theinsert 36 or a portion thereof to an acid. The acid may strip fluorinemolecules from the surface, making the surface less slippery (i.e., moreprone to forming a bond with an adhesive). As an additional example, theinserts 36 and/or surfaces defining recesses 34 may have ridges or otherphysical contours that may improve mechanical attachment. In someembodiments, an adhesive or glue may coat the interface between aninsert 36 and a surface defining recess 34. Adhesion techniques may becombined as appropriate (e.g., an insert 36 may be serrated and etched,and an adhesive may be applied). In some embodiments, inserts 36 may beinstalled into recesses 34 with a brazing process and/or a weldingprocess.

FIG. 11 is a perspective view showing a portion of a blade 12 of a drillbit 10 in accordance with some embodiments of the invention. The blade12 may include one or more inserts 36′. Inserts 36′ may be “chipsplitters,” configured to break up cuttings as the cuttings are formed,such as with one or more sharp edges. Inserts 36′ may comprise ananti-balling material to reduce drag on cutting fluid and cuttings.Inserts 36′ may be formed and installed into recesses (e.g., recesses34, 34′) with similar materials and methods as inserts 36 shown in FIGS.10A and 10B (e.g., may be formed of one material, and coated with adifferent, anti-balling material). In some embodiments, multiple chipsplitters may comprise an insert 36′.

Inserts 36 and 36′ may be removed from recesses 34 and 34′, such asafter the drill bit 10 has been in service. Inserts 36 and 36′ may beremoved because they are worn, damaged, or inappropriate for a selectedapplication. Inserts 36 and 36′ may be removed by mechanical and/orchemical means (e.g., adhesive removers, hot baths, abrasive blastingwith sand and/or metal shot, etc.). For example, inserts 36 and 36′ maybe comprised out of recesses 34 and 34′. After inserts 36 and 36′ havebeen removed, replacement inserts 36 and 36′ may be placed in therecesses 34 and 34′. Replacement inserts 36 and 36′ may have ananti-balling material as described above, and may be installed in thebit body 11 as described above. In some embodiments, replacement inserts36 and 36′ may be substantially similar to the inserts 36 and 36′ theyreplace. In some embodiments, replacement inserts 36 and 36′ may havedifferent properties than the inserts 36 and 36′ they replace, such aswhen a drill bit 10 is to be used for a different application from itsprevious use.

Referring to FIG. 12, in some embodiments of the invention, a pluralityof protrusions 40 may be formed or otherwise provided on the exteriorsurface 16 of the bit body 11 of the drill bit 10. As shown in FIG. 12,in some embodiments, the protrusions 40 may be generally elongated inshape, as previously described in relation to the recesses 32 of FIG. 6.The protrusions 40 may comprise discrete, laterally isolated protrusions40 that are separated from one another. Such discrete protrusions 40 maybe randomly located over the exterior surface 16 of the bit body 11, asshown in FIG. 12, or they may be disposed in an ordered array over aregion of the exterior surface 16 of the bit body 11. Furthermore, inadditional embodiments, the protrusions 40 may have any other shape suchas, for example, circular, oval, rectangular, square, triangular, etc.In embodiments having elongated protrusions 40, the protrusions 40 maybe oriented within the fluid course 13 to extend in a direction that isgenerally parallel to the general direction of fluid flow through thefluid course 13 during a drilling operation; they may be orientedtransverse to the direction of fluid flow through the fluid course 13;or some protrusions 40 may be oriented parallel to the direction offluid flow through the fluid course 13 and some may be orientedtransverse to the direction of fluid flow through the fluid course 13.For example, in some embodiments, a plurality of crisscrossing elongatedprotrusions may be provided in a region of the exterior surface 16within a fluid course 13. Thus, the protrusions 40 may be used to defineor provide a texture or pattern on the exterior surface 16 of the bitbody 11, in a manner similar to the previously described recesses 32 ofFIGS. 6 and 7, which may improve the usable life of the anti-ballingmaterial 22 when the anti-balling material 22 is disposed over thetexture or pattern.

FIG. 13 is a cross-sectional view of a portion of the drill bit 10 ofFIG. 12 taken along section line 113-113. As shown in FIG. 13, in someembodiments, the protrusions 40 may have an average height Hp of about0.254 mm (about 0.010 in) or more, about 0.381 mm (0.015 in) or more, oreven about 0.762 mm (about 0.030 in) or more. In some embodiments, theprotrusions 40 may have an average width W_(P) of about 0.787 mm (about0.031 in) or more, or even about 1.5 mm (about 0.060 in) or more. Inembodiments in which the protrusions 40 may be elongated, and may havean average length of about 6.35 mm (about 0.25 in) or more, about 19.05mm (about 0.75 in) or more, or even about 38.4 mm (1.5 in) or more.

The protrusions 40 may be formed on the bit body 11 of the drill bit 10using any of a number of techniques. For example, the protrusions 40 maybe formed on the exterior surface 16 of the bit body 11 using amachining process to machine away surrounding material of the bit body11, such as a milling process or a drilling process. Such processes maybe desirable when the bit body 11 is formed of and comprises a material,such as steel, that may be machined relatively easily. In additionalembodiments in which the bit body 11 is formed using an infiltrationprocess, the protrusions 40 may be formed on the exterior surface 16 ofthe bit body 11 by providing a surface within the mold cavity thatincludes recesses having a shape corresponding to the protrusions 40 tobe formed in the bit body 11. As the bit body 11 is cast within the moldcavity and adjacent the surface that includes the recesses, the recessesform complementary protrusions 40 in the exterior surface 16 of the bitbody 11, which become visible when the bit body 11 is removed from themold.

In some embodiments, recesses 32, 34, 34′, inserts 36, 36′, and/orprotrusions 40 may be configured to direct drilling mud, such as toenhance cleaning of the junk slots, limit blade erosion, break upcuttings, etc. Inserts 36, 36′ and/or protrusions 40 may be configuredto have low friction to reduce drag on drilling mud (including formationcuttings). Drag is known to reduce drilling efficiency and increase thechance of balling. Reducing drag may therefore increase drillingefficiency and decrease the chance of balling. Inserts 36, 36′ and/orprotrusions 40 may be configured as chip splitters (i.e., may beconfigured to break up cuttings before the cuttings ball). In suchembodiments, the chip splitters may comprise an anti-balling material 22having a low coefficient of friction (e.g., about 0.5 or less, about 0.2or less, or about 0.04 or less), such that drag on the drilling chips islimited. Chip splitters may comprise a support material (e.g., a metal,a metal alloy, a particle-matrix composite material, or a polymer) toreinforce the anti-balling material 22 of the chip splitter. Theanti-balling material 22 may have a lower coefficient of friction thanthe support material. Chip splitters may be positioned adjacent toblades, such as in recesses 34′ shown in FIG. 10.

FIGS. 14 through 17 illustrate various displacement members that may beused within a mold in an infiltration process for forming a bit body 11that include a texture or pattern configured to define a complementarytexture or pattern on an exterior surface 16 of a bit body 11 of a drillbit 10 in accordance with embodiments of the present invention.

Referring to FIG. 14, a displacement member 50 is illustrated that isconfigured to define at least a portion of a fluid course 13 of a bitbody 11 of a drill bit 10. A body 52 of the displacement member 50 maycomprise compacted resin-coated sand, and elongated strips 54 may beattached to a surface of the body 52 of the displacement member 50. Thestrips 54 may comprise, for example, elongated strips of graphite-basedmaterial, such as that sold by GrafTech International LTD. of Parma,Ohio, under the name GRAFOIL®. The strips 54 may be used to formtemplate protrusions on the body 52 of the displacement member 50. Thus,when the displacement member 50 is positioned within a mold and a bitbody 11 is cast within the mold and over and around the displacementmember 50 and the strips 54 using an infiltration process, the graphitestrips 54 may define complementary elongated recesses in the exteriorsurface 16 of the bit body 11 within the fluid course 13 defined by thebody 52 of the displacement member 50, similar to the recesses 32 shownin FIGS. 6 and 7. The strips 54 of the displacement member 50 shown inFIG. 14, however, are oriented on the displacement member body 52 insuch an orientation as to cause the resulting recesses formed in theexterior surface 16 of the bit body 11 to extend generally parallel tothe general direction of fluid flow through the fluid course 13 formedby the displacement member 50 during drilling.

FIG. 15 illustrates a displacement member 60 similar to the displacementmember 50 of FIG. 14, and includes a body 52 and elongated strips 54 aspreviously described. On the displacement member 60, however, theelongated strips 54 are oriented on the body 52 in such an orientationas to cause the resulting recesses formed in the exterior surface 16 ofthe bit body 11 to extend generally transverse to the general directionof fluid flow through the fluid course 13 formed by the displacementmember 60 during drilling.

FIG. 16 illustrates another displacement member 70 configured to definea texture or pattern on an exterior surface 16 of a bit body 11 of adrill bit 10. The displacement member 70 may comprise a clay materialthat has been shaped to include crisscrossing template recesses 72therein. Thus, when the displacement member 70 is positioned within amold and a bit body 11 is cast within the mold and over and around thedisplacement member 70 in an infiltration process, the template recesses72 may define complementary crisscrossing protrusions on the exteriorsurface 16 of the bit body 11.

FIG. 17 illustrates another displacement member 80 configured to definea texture or pattern on an exterior surface 16 of a bit body 11 of adrill bit 10. The displacement member 80 may comprise a graphite foilmaterial (such as that sold by GrafTech International LTD. of Parma,Ohio, under the name GRAFOIL®) that has been shaped to include an arrayof generally circular, discrete, and laterally isolated templateprotrusions 82 thereon. Thus, when the displacement member 80 ispositioned within a mold and a bit body 11 is cast within the mold andover and around the displacement member 70 in an infiltration process,the template protrusions 82 may define a complementary array of recesseson the exterior surface 16 of the bit body 11.

As shown in FIG. 18, after providing a pattern or texture in and/or onone or more regions of the exterior surface 16 of a bit body 11 of adrill bit 10, an anti-balling material 22 may be provided over thepattern or texture, as previously described herein. For instance, theanti-balling material 22 may be a sheet, and may be formed over contoursof regions of the exterior surface 16 of the bit body 11 of a drill bit10. In some embodiments, the sheet of anti-balling material 22 may haverecesses therein or protrusions therefrom, such as those described abovein reference to FIGS. 6 through 13. Recesses or protrusions of theanti-balling material 22 may be configured to direct the flow ofdrilling mud (including formation cuttings).

In additional embodiments of the present invention, a drill bit 10 likethat previously described herein (or any other downhole tool) mayinclude pre-formed inserts that comprise an anti-balling material 22.Such inserts may be separately formed from the bit body 11 andsubsequently attached thereto within complementary recesses formed inthe exterior surface 16 of the bit body 11 of the drill bit 10.Furthermore, such inserts may be replaceable.

For example, FIG. 19 illustrates an embodiment of an insert 90 of thepresent invention. The insert 90 includes an anti-balling body 92comprising an anti-balling material 22 as previously described herein.The anti-balling body 92 may be formed, using, for example, a moldingprocess (e.g., an injection molding process).

As shown in FIG. 19, the anti-balling body 92 of the insert 90 includesan outer surface 98 comprising the anti-balling material 22. The outersurface 98 may be configured to define an exposed, outer surface of thedrill bit 10. For example, the outer surface 98 may be configured todefine an exposed, outer surface of the drill bit 10 within a fluidcourse 13 thereof. The insert 90, and the complementary recess in thebit body 11 in which the insert 90 is to be received, may be sized,shaped, and otherwise configured such that the outer surface 98 of theinsert 90 is substantially continuous, flush, and co-extensive with thesurrounding exterior surface 16 of the bit body 11. Thus, although theouter surface 98 of the anti-balling body 92 is shown to be generallyrectangular and planar, the outer surface 98 may have any shape and anycontour that is desirable for the outer surface of the drill bit 10. Insome embodiments, the outer surface 98 may include channels, ribs,protrusions, or recesses to redirect drilling mud and cuttings.

The anti-balling body 92 and, hence, a layer of anti-balling material 22defined by the anti-balling body 92, may have an average thickness ofabout 0.20 mm (about 0.008 in), or even greater than about 3.175 mm(about 0.125 in).

The insert 90 optionally may comprise a base member 94. The base member94 may be configured for attaching the anti-balling body 92 to the bitbody 11 of a drill bit 10, and may comprise a different material thanthe anti-balling body 92. For example, the base member 94 may comprise ametal or metal alloy (e.g., steel), a particle-matrix compositematerial, such as a cemented carbide material (e.g., cemented tungstencarbide), or a polymer. In some embodiments, the base member 94 maycomprise a material that is at least substantially identical to thematerial used to form the bit body 11 of a drill bit 10 to which theinsert 90 is to be attached.

In some embodiments, the base member 94 may comprise a topographicalpattern and/or a porous mass, as previously described herein, and theanti-balling body 92 may be provided over (e.g., formed on) thetopographical pattern and/or a porous mass.

In some embodiments, the base member 94 may be integrally formed withthe anti-balling body 92. For example, the base member 94 may beinserted within a mold cavity used to form the anti-balling body 92, andthe anti-balling body 92 may be formed (i.e., molded) around the basemember 94. In additional embodiments, the base member 94 may be attachedto the anti-balling body 92 using fasteners (e.g., screws or bolts)and/or an adhesive. In such configurations, the insert 90 may beremovable from the bit body 11 of the drill bit 10, and, hence, may bereplaceable should the anti-balling body 92 wear to an unacceptablelevel during a drilling operation, thus facilitating repair andcontinued use of the drill bit 10.

By way of example and not limitation, the base member 94 may beconfigured to be bolted to the bit body 11 to attach the insert 90 tothe bit body 11, or the base member 94 may be configured to mechanicallylock with the bit body 11 such as, for example, with a tongue-and-groovetype joint therebetween (i.e., one of the bit body 11 and the basemember 94 including a tongue and the other including a complementarygroove for receiving the tongue therein). In yet additional embodiments,the anti-balling body 92 and/or the base member 94 may be attached tothe bit body 11 using a press-fit therebetween, a shrink-fittherebetween and/or using a brazing process and/or a welding process.

In yet additional embodiments of the invention, an anti-balling body 92,like that described in relation to FIG. 19, may be formed directlywithin a complementary recess formed in an exterior surface 16 of a bitbody 11 of a drill bit 10 using, for example, a casting process.

Although embodiments of the invention have been described hereinabovewith respect to a fixed-cutter earth-boring rotary drill bit,embodiments of the invention also include other types of downhole tools.As used herein, the term “downhole tool” means and includes any toolthat is used to form and/or service a wellbore. “Servicing” a wellboremeans and includes any operation in which a tool contacts a portion ofthe wellbore. Downhole tools include, for example, earth-boring toolssuch as drill bits (e.g., rotary drill bits such as fixed-cutter drillbits, roller cone drill bits, diamond impregnated drill bits, coringbits, and percussion bits), casing and liner drilling tools, reamers,and other hole-opening tools, as well as stabilizers, packers, andsteerable assemblies such as steerable liner systems.

Additional non-limiting example embodiments of the invention aredescribed below.

Embodiment 1

A downhole tool, comprising: a body having a surface comprising atopographical pattern defined by at least one of a recess extending intothe surface and a protrusion protruding from the surface; and ananti-balling material disposed over at least a portion of the surfacecomprising the pattern therein, the anti-balling material having acomposition selected to reduce accumulation of formation cuttingsthereon when the downhole tool is used to form or service a wellbore.

Embodiment 2

The downhole tool of embodiment 1, wherein the anti-balling materialcomprises a hydrophobic polymer, a metal, a metal alloy, a ceramic,diamond, diamond-like carbon, graphite, molybdenum disulfide, boronnitride, or silicone.

Embodiment 3

The downhole tool of embodiment 2, wherein the anti-balling materialcomprises a mixture of a metal or metal alloy and a hydrophobic polymermaterial.

Embodiment 4

The downhole tool of embodiment 1, wherein the anti-balling materialcomprises a material having a coefficient of friction of about 0.5 orlower.

Embodiment 5

The downhole tool of embodiment 1, wherein the anti-balling materialcomprises a material having a coefficient of friction of about 0.2 orlower.

Embodiment 6

The downhole tool of embodiment 1, wherein the anti-balling materialcomprises a layer of the anti-balling material disposed on the at leasta portion of the surface comprising the pattern.

Embodiment 7

The downhole tool of embodiment 6, wherein the layer of the anti-ballingmaterial has an average thickness of at least about 0.127 mm (about0.005 in).

Embodiment 8

The downhole tool of embodiment 7, wherein the layer of the anti-ballingmaterial has an average thickness of at least about 0.254 mm (about0.010 in).

Embodiment 9

The downhole tool of embodiment 1, wherein the topographical patterncomprises a plurality of discrete, laterally isolated protrusions.

Embodiment 10

The downhole tool of embodiment 9, wherein the discrete, laterallyisolated protrusions of the plurality of discrete, laterally isolatedprotrusions are disposed in an ordered array.

Embodiment 11

The downhole tool of embodiment 1, wherein the topographical patterncomprises a plurality of discrete, laterally isolated recesses.

Embodiment 12

The downhole tool of embodiment 11, wherein the discrete, laterallyisolated recesses of the plurality of discrete, laterally isolatedrecesses are disposed in an ordered array.

Embodiment 13

The downhole tool of embodiment 11, further comprising an insert,wherein the insert is disposed at least partially within a recess.

Embodiment 14

A downhole tool, comprising: a body having a surface comprising at leastone recess extending into the surface of the body; and an insertdisposed within the at least one recess, the insert comprising ananti-balling material having a composition selected to reduceaccumulation of formation cuttings thereon when the downhole tool isused to form or service a wellbore.

Embodiment 15

The downhole tool of embodiment 14, wherein the surface of the bodycomprises a plurality of recesses extending into the surface of thebody, and wherein the downhole tool further comprises an insert disposedin each recess of the plurality of recesses, each insert comprising theanti-balling material having the composition selected to reduceaccumulation of formation cuttings thereon when the downhole tool isused to form or service a wellbore.

Embodiment 16

The downhole tool of embodiment 14, wherein the plurality of recessescomprises a plurality of discrete, laterally isolated recesses.

Embodiment 17

A downhole tool, comprising: a body having a surface; at least oneporous mass over the surface of the body; and an anti-balling materialdisposed over the at least one porous mass, the anti-balling materialhaving a composition selected to reduce accumulation of formationcuttings thereon when the downhole tool is used to form or service awellbore.

Embodiment 18

The downhole tool of embodiment 17, wherein the at least one porous masscomprises a spray-deposited material.

Embodiment 19

The downhole tool of embodiment 18, wherein the body comprises tungstencarbide and the at least one porous mass comprises nickel aluminide.

Embodiment 20

The downhole tool of embodiment 17, wherein the anti-balling materialcomprises a fluoropolymer.

Embodiment 21

The downhole tool of embodiment 20, wherein the anti-balling materialcomprises a mixture of a metal or metal alloy and a fluoropolymer.

Embodiment 22

The downhole tool of embodiment 17, wherein the anti-balling materialcomprises a ceramic.

Embodiment 23

The downhole tool of embodiment 17, wherein the anti-balling materialcomprises diamond, diamond-like carbon, graphite, molybdenum disulfide,boron nitride, or silicone.

Embodiment 24

The downhole tool of embodiment 17, wherein at least a portion of theanti-balling material is infiltrated into pores of the at least oneporous mass.

Embodiment 25

The downhole tool of embodiment 17, wherein the anti-balling materialcomprises a layer of the anti-balling material disposed on the at leastone porous mass.

Embodiment 26

The downhole tool of embodiment 25, wherein the layer of theanti-balling material has an average thickness of at least about 0.0254mm (about 0.001 in).

Embodiment 27

The downhole tool of embodiment 25, wherein the layer of theanti-balling material has an average thickness of at least about 0.20 mm(about 0.008 in).

Embodiment 28

The downhole tool of embodiment 17, wherein the at least one porous masscomprises a plurality of porous masses defining a topographical patternon the surface of the body.

Embodiment 29

The downhole tool of embodiment 28, wherein the plurality of porousmasses comprises a plurality of discrete, laterally isolated porousdeposits.

Embodiment 30

The downhole tool of embodiment 29, wherein porous deposits of theplurality of discrete, laterally isolated porous deposits are disposedin an ordered array.

Embodiment 31

The downhole tool of embodiment 17, wherein the at least one porous masscomprises a layer of porous material.

Embodiment 32

A method of forming a downhole tool, comprising: forming at least one ofa recess extending into a body of the downhole tool and a protrusionprotruding from a body of the downhole tool; providing an anti-ballingmaterial over at least a portion of the surface; and selecting theanti-balling material to have a composition for reducing accumulation offormation cuttings thereon when the downhole tool is used to form orservice a wellbore. The downhole tool of embodiment 32 comprises asurface that extends into or over the recess or protrusion.

Embodiment 33

The method of embodiment 32, wherein forming at least one of a recessextending into a body of the downhole tool and a protrusion protrudingfrom a body of the downhole tool comprises: providing at least one of aplurality of template recesses and a plurality of template protrusionson a surface within a mold cavity having a shape configured to define atleast a portion of the body of the downhole tool; and casting the atleast a portion of the body of the downhole tool within the mold cavity.

Embodiment 34

The method of embodiment 33, wherein providing the at least one of aplurality of template recesses and a plurality of template protrusionson the surface within the mold cavity comprises: forming the at leastone of a plurality of template recesses and a plurality of templateprotrusions on a displacement member; and placing the displacementmember within the mold cavity prior to casting the at least a portion ofthe body of the downhole tool within the mold cavity.

Embodiment 35

The method of embodiment 34, further comprising selecting thedisplacement member to comprise at least one of a body comprising clay,a body comprising compacted resin-coated sand, and a body comprisinggraphite.

Embodiment 36

The method of embodiment 32, wherein forming at least one of a recessextending into a body of the downhole tool and a protrusion protrudingfrom a body of the downhole tool comprises machining the surface of abody of the downhole tool.

Embodiment 37

The method of embodiment 32, wherein providing the anti-balling materialover the at least a portion of the surface comprises thermally sprayingthe anti-balling material over the at least a portion of the surface.

Embodiment 38

The method of embodiment 32, wherein providing the anti-balling materialover the at least a portion of the surface comprises forming a layer ofthe anti-balling material and adhering the layer of the anti-ballingmaterial to the at least a portion of the surface.

Embodiment 39

A method of forming a downhole tool, comprising: providing a porous massover a surface of a body of the downhole tool; providing an anti-ballingmaterial over at least a portion of the porous mass; and selecting theanti-balling material to have a composition for reducing accumulation offormation cuttings thereon when the downhole tool is used to form orservice a wellbore.

Embodiment 40

A method of forming a downhole tool, comprising: forming a recess in asurface of a body of the downhole tool; forming an insert comprising ananti-balling material; selecting the anti-balling material to have acomposition for reducing accumulation of formation cuttings thereon whenthe downhole tool is used to form or service a wellbore; disposing theinsert within the recess; and attaching the insert to the body of thedownhole tool.

Embodiment 41

The method of embodiment 40, wherein forming an insert comprising ananti-balling material comprises: forming an insert comprising a metal,metal matrix, or polymer; and coating the insert with an anti-ballingmaterial.

Embodiment 42

The method of embodiment 40, wherein forming an insert comprising ananti-balling material comprises forming an insert comprising a materialwith a coefficient of friction of about 0.5 or lower.

Embodiment 43

The method of embodiment 40, wherein forming an insert comprising ananti-balling material comprises forming an insert comprising a materialwith a coefficient of friction of about 0.2 or lower.

Embodiment 44

The method of embodiment 40, wherein forming an insert comprising ananti-balling material comprises forming an insert comprising a ceramic,diamond, diamond-like carbon, graphite, molybdenum disulfide, boronnitride, or silicone.

Embodiment 45

A method of forming a downhole tool, comprising: forming a recess in asurface of a body of the downhole tool; forming an insert comprising atleast one of a metal, a metal matrix, or a polymer, the insertconfigured to fit at least partially within the recess; coating theinsert with an anti-balling material; and placing the insert at leastpartially within the recess.

Embodiment 46

A method of repairing a downhole tool, comprising: removing an insertfrom a recess of the downhole tool; disposing a replacement insertwithin the recess, the replacement insert having an anti-ballingmaterial selected to have a composition for reducing accumulation offormation cuttings thereon when the downhole tool is used to form orservice a wellbore; and attaching the replacement insert to the body ofthe downhole tool.

Although the foregoing description contains many specifics, these arenot to be construed as limiting the scope of the present invention, butmerely as providing certain exemplary embodiments. Similarly, otherembodiments of the invention may be devised that do not depart from thespirit or scope of the present invention. For example, featuresdescribed herein with reference to one embodiment also may be providedin others of the embodiments described herein. The scope of theinvention is, therefore, indicated and limited only by the appendedclaims and their legal equivalents, rather than by the foregoingdescription. All additions, deletions, and modifications to theinvention, as disclosed herein, which fall within the meaning and scopeof the claims, are encompassed by the present invention.

What is claimed is:
 1. A method of repairing a downhole tool,comprising: removing an insert from a recess on a bottom surface of afluid course located between a rotationally leading surface of a firstblade of a body of the downhole tool and a rotationally trailing surfaceof a second, adjacent blade of the body; disposing a replacement insertwithin the recess, the replacement insert having an anti-ballingmaterial selected to have a composition for reducing accumulation offormation cuttings thereon when the downhole tool is used to removeformation material from a subterranean formation; and attaching thereplacement insert to the body of the downhole tool at least partiallywithin the recess.
 2. The method of claim 1, wherein removing an insertfrom a recess comprises removing a worn insert from a recess of thedownhole tool.
 3. The method of claim 1, wherein removing an insert froma recess comprises prising the insert from the recess.
 4. The method ofclaim 1, wherein removing an insert from a recess comprises removing abolt coupled to the insert.
 5. The method of claim 1, wherein attachingthe replacement insert to the body of the downhole tool comprisesmechanically locking the replacement insert to the body of the downholetool.
 6. The method of claim 1, wherein attaching the replacement insertto the body of the downhole tool comprises pressing the replacementinsert into the recess.
 7. The method of claim 1, wherein attaching thereplacement insert to the body of the downhole tool comprises securingthe replacement insert in the recess by a shrink-fit.
 8. The method ofclaim 1, wherein attaching the replacement insert to the body of thedownhole tool comprises brazing the replacement insert into the recess.9. The method of claim 1, wherein attaching the replacement insert tothe body of the downhole tool comprises welding the replacement insertinto the recess.
 10. The method of claim 1, wherein the anti-ballingmaterial comprises at least one material selected from the groupconsisting of a fluoropolymer, a urethane, and an epoxy.
 11. The methodof claim 1, wherein the anti-balling material comprises at least onematerial selected from the group consisting of a metal, a metal alloy,and a ceramic.
 12. The method of claim 1, wherein the anti-ballingmaterial comprises at least one material selected from the groupconsisting of graphite, molybdenum disulfide, boron nitride, andsilicone.
 13. The method of claim 1, wherein attaching the replacementinsert to the body comprises securing a chip splitter having at leastone sharp exposed edge at least partially within the recess.
 14. Themethod of claim 1, wherein the replacement insert is configured to havea coefficient of friction different from a coefficient of friction ofthe insert.
 15. The method of claim 1, wherein the replacement insert isconfigured to have a coefficient of friction below about 0.04.
 16. Themethod of claim 1, wherein the replacement insert is configured to havea hydrophobicity different from a hydrophobicity of the insert.
 17. Themethod of claim 1, wherein the anti-balling material has a contact anglewith water droplets greater than 90°.
 18. The method of claim 1, whereinthe anti-balling material comprises a polymer and a metal material.